Tools for use downhole in the completion of a wellbore are generally well known. For example, perforation devices are commonly deployed downhole on wireline, slickline, cable, or on tubing string, and sealing devices such as bridge plugs and straddle packers are commonly used to isolate portions of the wellbore during fluid treatment of the wellbore. As such, tools are exposed to varying conditions during use, improvements have evolved over time to address problems typically encountered downhole.
Recently, tool assemblies for performing multiple functions in a single trip downhole have been developed, greatly reducing the cost of well completion operations. For example, CA 2,397,460 describes a bottom hole assembly for use in the sequential perforation and treatment of multiple wellbore intervals in a single trip downhole. Perforation with an explosive charge followed by sealing of the wellbore and application of treatment to the wellbore annulus is described. No active debris relief is described to maintain tool functionality in the presence of debris/solids, such as sand. Accordingly, the use of this tool in the presence of flowable solids would be associated with significant risk of debris-related tool malfunction, jamming or immobility of the tool assembly, and potential loss of the well if the tool assembly cannot be retrieved.
The use of jet nozzles in cleaning cased wellbores, and fracturing uncased wellbores, has been previously described in detail. Notably, CA 2,621,572 describes the deployment of a fluid jetting device above an inflatable packer. This type of packer provides minimal sealing against the uncased wellbore, allowing the assembly to travel up or downhole while the packers are inflated. This system is not suitable for use in perforation of a cased wellbore or in debris-laden environments, due in part to the imperfect seal provided by the inflatable packers, and the inability to clear solids that may settle over the packer and/or may block the jet nozzles.
Use of any sealing device in the presence of significant amounts of sand or other solids increases the risk of tool malfunction. Further, the tool may be lost downhole should a solids blockage occur during treatment, or when the formation expels solids upon release of hydraulic pressure in the wellbore annulus when treatment is complete. Moreover, when jetting abrasive fluid to perforate a wellbore casing, the prior art does not provide a suitable method for delivering clear fluid to the perforations/removing settled solids from the perforations in the event of a solids blockage. Typical completion assemblies have many moving components for actuating various downhole functions, and the presence of sand or other solids within these actuation mechanisms would risk jamming these mechanisms, causing a malfunction or permanent damage to the tool or well. Correcting such a situation is costly, and poses significant delays in the completion of the well. Accordingly, well operators, fracturing companies, and tool suppliers/service providers are typically very cautious in their use of sand and other flowable solids downhole. The addition of further components to the assembly adds further risk of solids blockages in tool actuation, and during travel of the tool from one segment of the wellbore to another, further risking damage to the assembly. Increasing the number of segments to be perforated and treated in a single trip also typically increases the size of the assembly, as additional perforating charges are required. Excessive assembly lengths become cumbersome to deploy, and increase the difficulty in removal of the assembly from the wellbore in the presence of flowable solids.